American energy independence, a goal that is tantalizingly close as of this writing, depends to a large extent on the ability of the United States to produce oil (and/or other hydrocarbons) in large quantities at low cost. While hydrofracturing (“fracking”) and other drilling technologies have dramatically reduced the cost of producing such hydrocarbons, the complex and time-varying chemistry of produced hydrocarbons can decrease the production of any given well (or group of wells) and can even cause a well to be shut down for maintenance/re-stimulation, work-overs, or shut-in permanently should conditions deteriorate far enough.
More specifically, such time-varying chemistry presents a number of technical problems. For instance, certain species in the produced fluid can cause corrosion in the well, the wellhead, production equipment, transportation pipelines, gathering facilities, and other points downstream therefrom. Moreover, hydrogen sulfide dissolved (or released) in the produced fluid can present an environmental and/or safety hazard (as well as contributing to some modes of corrosion). Bacteria in the fluid can foul filters, coat sensors, and contribute in their own ways to corrosion. Salts and other chemicals can precipitate out of solution and coat the internal surfaces of various components with scale, thus leading to decreased throughput, inaccurate sensor readings, reduced heat transfer capabilities, etc. Similarly, asphaltenes, paraffin's, hydrates, and/or the like can precipitate from the produced fluid thereby clogging pipelines and/or fouling many types of equipment.
Corrosion, which is often characterized by a loss of metal (or other materials) due to chemical (and/or electrochemical) reactions can eventually degrade and/or destroy structures in the production systems. Corrosion can occur anywhere in these systems, from the bottom of the “hole” (and any tools located therein) up to and including surface-based lines and/or equipment. The corrosion rate(s) will vary with time depending on the particular conditions of the oil field/systems such as the amount of water produced, secondary recovery operations, and pressure, temperature, and/or chemical concentration variations.
Hydrogen sulfide (H2S) presents another problematic chemical/corrosion issue often associated with produced fluids. At low concentrations, H2S has the odor of rotten eggs, but at higher, lethal concentrations, it is odorless. Accordingly, H2S is hazardous to workers with even a few seconds of exposure at relatively undetectable concentrations (by human senses) sometimes being lethal. But even exposure to lower concentrations can also be harmful to personnel with chronic exposure being associated with a number of health issues.
H2S can also cause sulfide-stress-corrosion cracking of metals. Because it is corrosive, the presence of H2S in produced fluids can require costly countermeasure such as using high-quality alloys, stainless steel (and/or other, more exotic materials) for tubing and the like. Such sulfides can be treated chemically, provided that they are detected in a timely fashion. More specifically, the sulfides can be precipitated from water, muds, oils, and/or oil muds by treating them with a sulfide scavenger. Follow up testing with (for instance) a Garrett Gas Train can also be conducted to determine sulfide concentrations in the treated fluids. Moreover tests can indicate the need/desire for caustic soda treatments to raise the fluid's pH and/or the need/desire for zinc-based scavengers to remove sulfides (in the form of ZnS).
Moreover, some produced fluids and/or “muds” host sulfur reducing bacteria (SRBs) and/or other so-called biologics. These anaerobic bacterium (the SRBs) can convert sulfate ions such as SO4-2 into S-2 and HS—, with the concomitant oxidation of a carbon source to H2S. The lignite, lignin, tannins, cellulose, starches, fatty acids, and other organic species found in many produced fluids and/or muds provide carbon based food sources and mineral nutrients for such SRBs. Accordingly, produced fluids can have high (and time-varying) SRB concentrations. Moreover, H2S combined with iron can form iron sulfide, a scale that is very difficult to remove.
SRBs, furthermore, occur naturally in surface waters, including seawater and other potential contamination sources that might be introduced into a well for various purposes (for instance as fracking water). Of course, other biologic species can present corrosion issues as well. Thus, bacteria accumulation can lead to pitting of steel and/or buildups of H2S which increases the corrosiveness of the water (and/or other fluids), thereby increasing the possibility of hydrogen blistering and/or sulfide stress cracking which can result in integrity failures and unintended release of hydrocarbons/produced fluids into the environment.
Before storage of hydrocarbons, muds, fluids, and/or other materials potentially containing SRBs, treatment with a bactericide can inhibit SRB growth. Also, circulating these fluids from time to time, with air injection/entrainment, can retard development of anaerobic conditions which favor the growth of SRBs. In situations in which aerobic biologics are found, blanketing the fluids/muds with an inert gas can retard the growth/propagation of these biologic species but only if they are detected and identified in a timely manner.
Produced fluids can also contain materials which lead to scaling of internal surfaces. Many scales form from mineral salt deposits that may occur in the produced fluids. In many situations, a produced fluid is (or becomes) saturated with certain chemicals during its travel through the various systems disclosed elsewhere herein. More specifically, the fluid might travel from a regime in which the pressures, temperatures, pH, etc. preclude precipitation in any meaningful amount to a regime in which one or more factors have changed leading to saturation conditions and thus precipitation of one or more scale-producing species.
With relatively severe conditions, scale can create a significant flow restriction, or even a plug, in a production system. While scale removal is a common well-intervention operation (with a wide range of mechanical, chemical and scale inhibitor treatment options available), it still introduces labor and consumable costs. Moreover the scale removal additives can affect the chemistry of the produced fluid (for instance altering its pH) which in turn leads to other chemistry related issues (for instance, fostering SRB growth). Additionally, it should be noted that scale-precipitation events are variable in nature, and will typically manifest themselves in a non-static fashion as temperature, pressure, and contaminant concentrations vary over time and in response to discrete events. Again, though, corrective measures depend on timely identification of the potentially problematic species in the comingled fluids.
Asphaltenes paraffins hydrates, and other similar precipitating species can present still other issues for the well operator, owner, and/or other users. For instance, paraffins are hydrocarbon compounds that often precipitate on/in production components as a result of the changing temperatures and pressures within these systems. Heavier paraffins occur as wax-like substances that may build up on internal surface/components and can restrict (or even stop) production flowrates. Paraffins are normally found in the tubing close to surface. Nevertheless, it can form at the perforations of the well casing, or even inside the formation, especially in depleted reservoirs or reservoirs under gas-cycling conditions. Asphaltenes and hydrates present similar issues as those caused by paraffins.
Moreover, the presence of many of these species mask each other's presence. Thus, the comingled species in produced hydrocarbons present a number of chemistry related problems that, for efficient, reliable operation of a system ought to be detected so that they can be dealt with. However, heretofore available systems cannot reliably detect much less identify the various species in comingled fluids in many processes.